Methodology and system for producing fluids from a condensate gas reservoir

ABSTRACT

A method of producing reservoir fluids from a condensate gas reservoir traversed by a production well includes the formation of a protrusion into natural gas bearing rock along a producing interval of the reservoir. A heater element is placed into the protrusion and configured for operation. Reservoir fluids are produced from the producing interval while the heater element heats the natural gas bearing rock proximate the heater element. The heat supplied by the heater element reduces condensate build up in the natural gas bearing rock adjacent the production well during production. The heater element is configured to heat the natural gas bearing rock that is proximate the heater element to a temperature that is sufficient to vaporize and/or reduce the viscosity of condensate that is proximate the heater element. A related system is also described.

CROSS REFERENCE TO RELATED APPLICATION

This application claims benefit of U.S. Provisional Patent ApplicationSer. No. 61/671,509 filed Jul. 13, 2012, the contents of which areincorporated herein by reference.

FIELD

This case relates to wells that produce gas and condensate.

BACKGROUND

Condensate blocking is a common problem in gas wells. The techniquesused to cope with this problem can include fracturing, drilling newwells, injecting solvents, etc. It is well known that the pressure andtemperature play an important role in the phase behavior of a compound;variation of these parameters can cause the compound to transitionbetween gas phase, liquid phase, and solid phase.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

According to one aspect, a method of producing reservoir fluids from acondensate gas reservoir traversed by a production well includes formingat least one protrusion into natural gas bearing rock along a producinginterval of the production well. The protrusion extends in a radialdirection away from the central axis of the production well into thenatural gas bearing rock, and the protrusion is configured to receive aheater element. The heater element is placed into the protrusion andconfigured for operation by surface located equipment. While producingreservoir fluids from the producing interval of the production well, therespective heater element is operated to heat the natural gas bearingrock that is proximate the heater element. The heat supplied by theheater element reduces buildup of condensate in the natural gas bearingrock adjacent the producing interval of the production well during theproduction of reservoir fluids from the producing interval.

In one embodiment, the heater element is configured to heat the naturalgas bearing rock that is proximate the heater element to a temperaturethat is sufficient to vaporize and/or reduce the viscosity of condensatethat is proximate the heater element. The protrusion can be formed by adevice selected from the group consisting of a perforation gun, a highpower laser, a casing drilling instrument, and a directional drillingtool. The protrusion may also be formed by any other desirable means.

In one embodiment, the reservoir fluids are produced through at leastone perforation in a casing. The at least one perforation can extendinto the natural gas bearing rock along the producing interval of theproduction well. The at least one perforation provides fluidcommunication between the natural gas bearing rock and the producinginterval of the production well.

In one embodiment, a perforation in a casing is located above andproximate to an associated protrusion for a respective heater element.The heat supplied by the respective heater element can vaporizecondensate to form a gas that flows to the associated perforation forproduction of the gas therethrough. The heat supplied by the respectiveheater element can also reduce the viscosity of liquid phase condensatethat is proximate the heater element to promote the flow of the liquidphase condensate to the associated perforation for production of theliquid phase condensate gas therethrough.

The at least one perforation can be formed by a device selected from thegroup consisting of a perforation gun, a high power laser, a casingdrilling instrument, and a direction drilling tool. The at least oneperforation can be formed or enhanced by hydraulic fracturing.

In another method embodiment, the heater element is supplied with heatfrom an external heat source and transfers the heat into the gas bearingrock matrix that is proximate to the heater element.

The method can further include injecting metal nanoparticles into thegas bearing rock in the vicinity of the heater element to promotelocalized heating of such gas bearing rock. The metal nanoparticles areinjected into the gas bearing rock in an area where condensate forms oris likely to form during production.

The method can also include monitoring operations, such as monitoringthe flow rate of produced reservoir fluids, monitoring temperatureand/or pressure of the condensate reservoir as a function of locationalong the producing interval, and monitoring temperature and/or pressureof the condensate reservoir in the vicinity of the heater element as afunction of radial offset away from the producing interval.

In another aspect of the present application, a system for producingreservoir fluids from a condensate gas reservoir traversed by aproduction well includes at least one heater element that is configuredfor disposition inside a respective protrusion into natural gas bearingrock along a producing interval of the production well. The protrusionand corresponding heater element extend in a radial direction away fromthe central axis of the production well into the natural gas bearingrock. Equipment, surface located, is configured to operate the at leastone heater element. The heater element is configured to heat the naturalgas bearing rock that is proximate the heater element. Heat supplied bythe heater element reduces the buildup of condensate in the natural gasbearing rock adjacent the producing interval of the production wellduring the production of reservoir fluids from the producing interval.In one embodiment, the heater element is configured to heat the naturalgas bearing rock that is proximate the heater element to a temperaturethat is sufficient to vaporize and/or reduce the viscosity of condensatethat is proximate the heater element.

The protrusion for a respective heater element can be located below andproximate to at least one perforation in a casing that can extend intothe natural gas bearing rock along the producing interval of theproduction well. The perforation provides fluid communication betweenthe natural gas bearing rock and the producing interval of theproduction well. The heat supplied by the respective heater element canvaporize condensate to form a gas that flows to the perforation forproduction of the gas therethrough. The heat supplied by the respectiveheater element can also reduce the viscosity of liquid phase condensatethat is proximate the heater element to promote the flow of the liquidphase condensate to the perforation for production of the liquid phasecondensate gas therethrough.

In one embodiment, the heater element is realized by a resistive heaterelement.

In another embodiment, the heater element is realized by an antenna thatdirects electromagnetic radiation into the natural gas bearing rock. Adownhole source of electromagnetic radiation can be provided (in theproducing interval of the production well) together with cables or awaveguide that supplies the electromagnetic radiation generated by thesource to the antenna.

In yet another embodiment, the heater element is supplied with heat froman external heat source and transfers the heat into the gas bearing rockmatrix that is proximate to the heater element.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a phase diagram of a typical gas condensate.

FIG. 2 is a cross sectional view of a gas condensate reservoir traversedby a vertical gas producing well.

FIG. 3 shows the pressure measurements of a production well for asequence of first draw down cycle (labeled “1DD”) followed by a firstbuild up cycle (labeled “2BU”) followed by a second drawn down cycle(labeled “3DD”) followed by a second build up cycle (labeled “4BU”).

FIGS. 4A and 4B are graphs of condensate saturation (the percent offormation porosity filled with condensate) for gas condensatereservoirs, where the condensate saturation is plotted against radiusinto the respective formation.

FIG. 5 is a flow chart outlining a methodology for producing reservoirfluids from a condensate gas reservoir.

FIG. 6 is a schematic diagram of a condensate gas production well thatemploys the condensate heating methodology of FIG. 5.

FIG. 7 is a schematic diagram that illustrates the heating profile ofthe heater element of FIG. 6.

FIG. 8 is a schematic diagram of a condensate gas production well thatcarries out monitoring operations in conjunction with the condensateheating methodology of FIG. 5.

DETAILED DESCRIPTION

FIG. 1 shows the phase diagram of a typical gas condensate (also calledretrograde gas). This diagram shows how gas condensate can transitionback and forth between gas phase and liquid phase. Point 1 in FIG. 1corresponds to a gas phase. The line from point 1 to 3 is an isothermwherein the temperature is kept constant while the pressure is reduced.When the pressure becomes equal to that of point 2 (on the saturationline), liquid starts to form and coexist with the gas phase. Continuingto reduce the pressure, as indicated by point 3, further liquid isformed. Point 2 is referred to as the dew point or condensation point ifit is located above the critical point, and is referred to as the bubblepoint if it is located below the critical point.

Reservoir hydrocarbons are a mixture of different hydrocarbon speciesthat are present as either a liquid phase or gaseous phase depending onlocation from the critical point at the saturation line. For natural gasreservoirs, the industry distinguishes between two different types, drygas reservoirs and condensate gas reservoirs (also referred to wet gasreservoirs). Dry gas reservoirs contain more than 90% methane and tracesof C₂-C₅ which will remain in the gas phase for all practical cases. Thedry gas reservoirs do not produce condensates. Condensate gas reservoirsare composed of C₁ to C₁₂ hydrocarbon species (where Ci is a hydrocarbonwith i carbon atoms and the corresponding hydrogen atoms). Since thehydrocarbon species with carbon numbers greater than 4 have thepotential of liquefying, the gas components with Cn (n>4) from thesereservoirs can condense into liquid under the appropriate temperatureand pressure; thus, the name condensate gas (or wet gas). Condensate gasreservoirs normally have high enough temperature and pressure that,before the production starts, all components are in the single (gas)phase. Once production starts, it causes the pressure to decline,causing the temperature and pressure to touch the saturation line, asshown in point 2 of FIG. 1. As a result, the gas begins to condense andliquid begins to form. At this point, the heaviest component of fluidmixture constitutes the liquid phase. At point 2, vapor and liquidcoexist within the two phase region of the phase envelope. Furtherpressure reduction causes the next heavier component to liquefy, andthis is followed by the next heavy component, etc. The majority of theproduced fluid is typically gas; generally a gas condensate reservoirproduces less than 25% liquid condensate. The liquid dropout(condensate) does not flow as fast as the gas and falls behind. As thistrend continues the volume of condensate increases and can interferewith gas production.

FIG. 2 is a cross sectional view of a gas condensate reservoir traversedby a vertical gas producing well, where production from the well hasresulted in build-up of condensate at the bottom of the reservoir. Thecondensate is expected to build up from the bottom because as a liquidit has higher density than the gas phase. It is common to divide part ofthe reservoir close to the production well into three cylindrical zones(zone 1, zone 2 and zone 3) as shown in FIG. 2. Zone 3, which is faraway from the well, is the unperturbed reservoir and is characterized bya single (gas) phase. In this zone the gas pressure and temperature areabove the dew point preventing any phase change. Unless any liquid hasbeen present initially, there will not be any condensate or liquidformed as a result of production (yet). This is in contrast with zones 2and 1 wherein the temperature and pressure are such that the system isalready below the dew point and two phases (liquid and gas) coexist. Asmore and more gas is produced, the pressure drops and the boundariesbetween the zones shift. In the intermediate zone 2, only the gas flowswhile the condensate remains low but stagnant. In zone 1, which isadjacent to the borehole wall, both condensate and the gas flow,although the condensate flows at a slower rate, and accumulates as afunction of time. The condensate volume in zone 1 reduces the flow rateof the gas and eventually can completely block the flow of the gas intothe well.

Details about these zones and the reservoir can be obtained frompressure measurements on the well. FIG. 3 shows the pressuremeasurements for a sequence of a first draw down cycle (labeled “1DD”)followed by a first build up cycle (labeled “2BU”) followed by a seconddrawn down cycle (labeled “3DD”) followed by a second build up cycle(labeled “4BU”). During the first and second build up cycles, theproduction is stopped (usually completely) leading to a pressureincrease. The well is kept at that condition for a period of time toallow all zones to come to an equilibrium state. During the first andsecond drawn down cycles, production occurs from the well, which causesthe pressure to drop. The pressure variation over time can be analyzedto determine the reservoir properties.

For example, it is common to analyze the pressure measurements obtainedfrom a sequence of draw down cycles and build up cycles (such as thesequence of FIG. 3) to characterize the size of the reservoir, thepressure at different zones, the size of different zones, etc. Two suchresults are shown in FIGS. 4A and 4B where the condensate saturation(the percent of formation porosity filled with condensate) is plottedagainst radius into the formation. In these figures, far enough awayfrom the borehole (about 40 ft in FIG. 4A, and about 100 ft in FIG.4B—note the logarithmic x axis) the liquid saturation goes to zeromarking the boundary for Zone 3. The boundary between zones 1 and 2 isassigned based on an abrupt change of slope in saturation which is atabout 5 ft for FIG. 4A and at about 20 ft for FIG. 4B. The differentsaturation behavior for the draw-down and build up cycles are also seento happen mostly at depth closer to the borehole (Zone 1). As expected,during draw-down, gas is produced and more condensate is formed. In FIG.4A there is an increase in liquid saturation from 0 to 1 foot into theborehole (compared draw-down DD5 to buildup BU6) while the remainder ofzone 1 stays unchanged. Similarly, in FIG. 4B there is an increase inliquid saturation in Zone 1 and to a lesser extent in Zone 2 for thedraw-down as compared to the buildup. In both Figures the liquidsaturation is larger at radial distances closer to the borehole. Theseobservations are consistent with more condensate being formed closer tothe borehole wall. The measurements of FIGS. 4A and 4B also imply thatto the extent that condensate is formed in zone 3, it will be producedclosest to the well. This is expected since the pressure drop betweenthe reservoir and the borehole is greatest in that region. However, withtime, the condensate redistributes along this zone causing the averagelevel to go up along the entire length of zone 3 (see FIG. 4B). Turningto FIG. 5, there is shown a method for producing reservoir fluids from acondensate gas reservoir. The method begins in step 101 by drilling aborehole that traverses the condensate gas reservoir. The borehole canbe vertical, multi-lateral or horizontal. The condensate gas of thereservoir is a single-phase fluid at original reservoir conditions. Itconsists predominantly of methane and other short chain hydrocarbons,but it also contains long chain hydrocarbons, termed heavy ends. Undercertain conditions of temperature and pressure, this fluid will separateinto two phases, a gas and liquid that is called a retrogradecondensate. As a reservoir produces, pressure decreases. The largestpressure drops occur near the producing well. When the pressure in thecondensate gas reservoir decreases to a certain point, called thesaturation pressure or dewpoint, a liquid phase rich in heavy ends dropsout of solution and the gas phase is slightly depleted of heavy ends. Acontinued decrease in pressure increases the volume of the liquid phaseup to a maximum amount. Pressure decreases beyond this point decreaseliquid volume.

In step 103, the borehole is cased. Typically, the casing includesmultiple intervals of casing successively placed within the previouscasing run. Cement can fill the annulus between the casing and theborehole for stability and sealing the rock formations containingliquids or gases. The casing includes production casing that extends toa producing interval of the borehole that traverses the condensate gasreservoir.

In step 105, the producing interval of the borehole is completed toallow for inflow of condensate gas at one or more locations along theproducing interval. The completion of step 105 can be an open holecompletion (where no casing or liner is cemented in place across theproducing interval), a cased hole completion (where a casing or a linerextends through the producing interval and is cemented in place) orother suitable well completion.

The common options for open hole completions for condensate gas wellsare pre-holed liners (also often called pre-drilled liners) or slottedliners. The pre-holed liner is prepared with multiple small drilledholes, and set across the producing interval to provide wellborestability and an intervention conduit. The slotted liner is machinedwith multiple longitudinal slots, for example 2 mm×50 mm, spread acrossthe length and circumference of each joint. The open hole completionscan be combined with open hole packers, such as swelling elastomers,mechanical packers or external casing packers, to provide zonalsegregation and isolation. Multiple sliding sleeves can also be used inconjunction with open hole packers to provide considerable flexibilityin zonal flow control for the life of the well.

For cased hole completions, connection between the annulus of theproduction casing and the formation is made by perforating. Because theperforations can be precisely positioned, this type of completionaffords good control of fluid flow, although it relies on the quality ofthe cement to prevent fluid flow behind the casing/liner. Theperforating can be accomplished by a perforating gun that is positionedas desired in the annulus of the production casing. The gun carriesshape charges that are detonated to punch a pattern of perforationsthrough the production casing and surrounding cement into thegas-bearing rock matrix that surrounds the casing. Typical perforatingguns can form perforations that extend radially into the rock matrix,typically in a range of 6 inches to 20 inches in length relative to theouter wall of the production casing. It is also contemplated that theperforating can be accomplished by other means, such as with high powerlaser energy (possibly in conjunction with liquid jet pulses). The casedhole completions can be combined with cased hole packers to providezonal segregation and isolation.

As part of step 105, the perforation into the rock matrix adjacent theproducing interval can be formed (or enhanced) utilizing hydraulicfracturing where the fracturing fluid is supplied to the rock matrix atpressures that exceed that of the fracture gradient of the rock matrix.The fracture gradient is defined as the pressure required to inducefractures in rock matrix at a given depth and is usually measured inpounds per square inch per foot or bars per meter. The pressurizedfracturing fluid flows through holes or voids in the production casingcausing the rock to crack, and the fracture fluid continues farther intothe rock matrix, extending the crack still farther, and so on. Operatorstypically try to maintain “fracture width,” or slow its decline. Aproppant (such as grains of sand, ceramic, or other particulates) can beintroduced into the fracture. The proppant is intended to prevent thefracture from closing when the injection is stopped and the pressure ofthe fracturing fluid is reduced. The fracturing fluid can include anacid (typically hydrochloric acid). The acid tends to etch the fracturefaces in a non-uniform pattern, forming conductive channels that remainopen without a propping agent after the fracture closes.

In an alternate embodiment, as part of step 105, the perforation intothe rock matrix adjacent the producing interval can be formed by othersuitable methods. For example, a casing drilling instrument (such as theCased Hole Dynamics Tester offered commercially by Schlumberger) can beused to form a perforation into the rock matrix adjacent the producinginterval. The Cased Hole Dynamics Tester can be delivered to thelocation of interest, anchored, and a drill bit from the tool body isused to drill into the casing (if presented) and formation. In anotherexample, a direction drilling tool (such as the Extreme tool offeredcommercially by Schlumberger) can be used to form a perforation (lateralbranch) into the rock matrix adjacent the producing interval of theborehole. The directional drilling can also be done by coiled-tubing asis well known in the industry. These techniques offer flexibility in thediameter and depth of the perforation.

The perforation of step 105 extends into the rock matrix in a radialdirection away from the central axis of the borehole of the well andpromotes migration of natural gas from the rock matrix into the wellannulus for production. It is also contemplated that such perforationcan be treated with an acid. For carbonate rock matrix, the acid candissolve the matrix to extend the length of the perforation.

The perforation operations of step 105 can be performed at differentradial directions for a given producing location adjacent the naturalgas bearing rock matrix. The perforation operations of step 105 can alsobe carried out at multiple locations that are separated from one anotheralong the central axis of the borehole of the well.

In step 107, at a location proximate the production location(s) of step105, a heater protrusion is formed into the rock matrix. The heaterprotrusion can be formed by a perforating gun that is positioned asdesired in the annulus of the well. The gun carries a shape charge thatis detonated to punch a perforation (through production casing andsurrounding cement, if present) into the adjacent gas-bearing rockmatrix. Typical perforating guns can form perforations that extendradially into the rock matrix in a range of 6 inches to 20 inches inlength relative to the outer wall of the production casing, althoughthis application is not limited thereto. In the event that the sectionof interest is not cased by steel casing and cement, the shape chargedoes not have to penetrate through the steel casing and cement, and theenergy of the shape charge will penetrate even deeper into the rockmatrix beyond 20 inches. It is also contemplated that the heaterprotrusion can be formed by other means, such as: a high power laserenergy (possibly in conjunction with liquid jet pulses); a casingdrilling instrument (such as the Cased Hole Dynamics Tester offeredcommercially by Schlumberger), where the Cased Hole Dynamics Tester canbe delivered to the location of interest, anchored, and a drill bit fromthe tool body can be used to drill into the casing (if presented) andformation; and a direction drilling tool (such as the Extreme tooloffered commercially by Schlumberger) that can be used to form theheater protrusion (lateral branch) into the rock matrix (the directionaldrilling can also be done by coiled-tubing as is well known in theindustry.) These techniques offer flexibility in the diameter and depthof the heater protrusion.

The heater protrusion of step 107 extends into the rock matrix in aradial direction away from the central axis of the borehole of the well.The heater protrusion 107 is sized to receive a heater element asdescribed below with respect to step 109. In one embodiment, the heaterprotrusion extends from the borehole in a direction parallel to that ofthe proximate production perforation of step 107.

The operations of step 107 can be performed at different radialdirections for corresponding perforations that extend into the matrix asa result of step 105. The operations of step 107 can also be carried outat multiple locations in or adjacent the producing interval that isseparated from one another along the central axis of the borehole of thewell for corresponding production perforations that result from step105.

In step 109, a heater element is placed into the heater protrusionformed in step 107, and the heater element (or support equipment for theheater element) is coupled to surface control equipment. In oneembodiment the heater element operates under control of the surfacecontrol equipment to heat the adjacent rock matrix to a temperature thatmobilizes (and/or vaporizes) condensate near the producing interval ofthe well in order to limit the buildup of condensate near the producinginterval of the well. The operations of step 109 can be repeated formultiple heater elements to place and configure the multiple heaterelements in the heater protrusion formed in step 107.

The heater element of step 109 can be realized by a ruggedizedresistance heating element suitable for the downhole environment. Theresistance heating element can be energized by electrical energygenerated by the surface control equipment and supplied to the heaterelement by conductors that extend therebetween. The conductors can passdown through completion pipe or through a dedicated completion pipe. Itis also possible to place the conductors in a small metal tube on theoutside of the casing inside the surrounding cement zone.

In an alternate embodiment, the heater element of step 109 can employelectromagnetic radiation to heat the adjacent rock matrix. Thistechnology employs a downhole source of electromagnetic radiation (forexample, a magnetron), a waveguide or cable (depending on the frequency)to deliver the electromagnetic radiation to an antenna (such as horn ordipole antenna) that is positioned in the heater protrusion. The antennaradiates the energy into the adjacent rock matrix to heat the adjacentrock matrix. The downhole source can be placed inside the annulus of thewell (in the producing interval in close proximity to the antenna) andcontrolled by surface control equipment via conductors that extendtherebetween. The conductors can pass down through completion pipe orthrough a dedicated completion pipe. It is also possible to place theconductors in a small metal tube on the outside of the casing inside thesurrounding cement zone.

Electromagnetic heating has the advantage that with proper design of theantenna, the energy can be directed to the direction of interest. Forexample, the energy can be directed to the end of the heater protrusionsuch that it penetrates beyond the physical size of the heatingprotrusion. Alternatively, it can be directed above or below the heaterprotrusion if desired. The frequency of the electromagnetic energy isanother parameter that can be advantageously used. When theelectromagnetic radiation enters a medium such as a rock, its intensitydecreases exponentially as a function of travel distance into the rockmatrix. Thus, the depth of penetration is defined as the depth into themedium wherein the intensity has reduced to 1/e of the initialintensity, where e=2.7 is the base of natural logarithm. This depth ofpenetration (δ) is known as the skin depth and is given by the followingequation:

$\begin{matrix}{\delta = \sqrt{\frac{2}{2\pi \; f\; \sigma \; \mu}}} & {{Eqn}.\mspace{14mu} (1)}\end{matrix}$

where f is the frequency, σ is the conductivity of the medium, and μ isthe magnetic permeability (which for normal rocks is equal to that offree space).

As the equation shows, lowering the frequency increases the skin depthand one can use the electromagnetic radiation to heat the rock matrix ata greater distance from the heater protrusion.

Metal particles have a large cross section for absorbing theelectromagnetic radiation produced by the antenna. This causes a metalparticle that is in the field of the antenna to preferentially absorbthe radiation such that is gets hotter than its environment. Use ofmetal particles is one way of concentrating the heat and creatinglocally higher temperatures compared to the surrounding medium. Notethat the amount of energy is not changed, but it is distributeddifferently.

In one embodiment, metal particles are injected into the rock matrix inan area where condensate forms (or is likely to form) during production.Metal particles have a large cross section for absorbing theelectromagnetic radiation produced by the antenna. This causes a metalparticle that is in the field of the antenna to preferentially absorbthe radiation such that is gets hotter than its environment

Where metal particles are injected into the rock matrix, the metalparticles are distributed over the area of condensate formulation in auniform manner and operate to absorb the electromagnetic energy emittedby the antenna and raise the temperature locally, thus serving as thelocal hot points with higher temperature than the surroundings. The hightemperature of the metal particles induced by the electromagnetic energyemitted by the antenna can aid in vaporizing condensate. The gas canform gas pockets that can push the remaining condensate to the producinginterval of the well. This process is specifically effective inpositions far enough away from the antenna that the average heatingtemperature is below the temperature that vaporizes the condensate.

The metal particles should be small enough to pass through the rock poresize. In one embodiment metal particles having sizes in the nano-meterrange (so called nanoparticles) are utilized. There are well-knownmethods of generating these particles. The particles can be made in adistribution of sizes so that they penetrate different throat sizes. Themetal nanoparticles can be treated with one or more bonding agents thathelp them to attach to the pore walls of the rock matrix. For pore wallsthat are oil wet, such bonding agents can include an organic group thatpreferentially bonds to the oil wet pore walls. For pore walls that arewater wet, such bonding agents can include polar groups (such ascarboxylates, for example) that preferentially attach to the water wetpore walls. In operation, the wettability of the pore walls of the rockmatrix is measured and based on this measurement one or a combination ofthese particles are introduced into the rock matrix. By way of exampleonly, the interval of interest can be isolated by two packers and asolution containing these solubilized metal particles can be introducedin the isolated interval at a pressure that is higher than the formationpressure. The excess pressure pushes the particles into the rock matrixwhere they bond to the pore wall. The pressure is then removed allowingthe formation fluid to flow normally.

The metal particles can also concentrate heat from other heatingmethods. For example if a resistive heating element is used to generatethe heat, the dispersed metal particles can concentrate heat and aidwith condensate vaporization. Thus, the metal particles are not limitedto electromagnetic heating although they can be more efficient when usedin conjunction with electromagnetic heating.

The heater element of step 109 can also be a heat exchanger or othersuitable heat conducting element that distributes heat generated byother means, such as steam generated at the surface and supplied to theheat exchanger, steam generated by a downhole steam generator, or heatgenerated by a downhole combustor (for example, oxygen gas can bedelivered downhole to the combustor and used to burn some of the gas orcondensate that is produced by the well).

In step 111, production tubing is installed that extends from theproducing interval to the wellhead.

In step 113, the production tubing is used to produce natural gas (andpossibly condensate) from the completed producing interval of the wellwhile concurrently using the surface control equipment to operate theheater element(s) to heat the adjacent rock matrix to a temperature thatmobilizes (and/or vaporizes) condensate near the completed producinginterval of the well in order to limit buildup of condensate near thecompleted producing interval of the well. The heater element can becontrolled by a device located in the vicinity of the production zone.In this case one of the production parameters, such as the rate of gasor condensate production is monitored and is compared with a targetvalue. This can be done by having a microprocessor or a similar devicelocated downhole. Based on the comparison, the device may increase ordecrease the current into the heater element(s). For example if the gasproduction rate is the parameter of interest and the measurement shows adecreased rate compared to the target value, it implies that the extentof heating is not sufficient and more current needs to be supplied tothe heater element. This adjustment can be done by the downhole device(not shown).

In one embodiment, the heater element is adapted to heat the adjacentrock matrix to a temperature that vaporizes condensate near theproducing interval of the well. This effect is shown graphically in FIG.1 where the liquid phase condensate of point 3 is heated to cause ahorizontal shift. Heating to point 4 causes the condensate to vaporizeinto a gas phase all the way to the dew-point line where there is almostzero liquid drop-out. Heating to a lesser temperature (such as point 5along this line) causes the liquid condensate to vaporize to the gasphase while allowing some remaining liquid phase condensate (about 6%).Once gas is generated, it will flow in the direction of low pressure,which in this case, is the completed producing interval of the well. Inaddition to vaporization, the temperature increase can also reduce theviscosity of the liquid phase condensate, thus improving the mobility ofthe liquid phase condensate and causing it to flow into the completedproducing interval of the well. Both these mechanisms reduce the amountof condensate and help increase the gas flow rate.

FIG. 6 shows a condensate gas production well with a production casing201 that lines a production interval 203 of a borehole that traverses agas-bearing rock matrix 205. The production casing 201 includes aprotrusion 207 into the gas-bearing rock matrix 205 adjacent theproducing interval 203 as described above with respect to step 105. Theprotrusion 207 extends into the rock matrix 205 in a generally radialdirection away from the central axis of the borehole and promotesmigration of natural gas and possibly condensate from the rock matrix205 into the well annulus for production. The production casing 201 alsoincludes a heater protrusion 209 that is located proximate to theprotrusion 207. The heater protrusion 209 extends into the rock matrix205 in a radial direction away from the central axis of the borehole(e.g., in a direction substantially parallel to that of the proximateproduction protrusion 207). The heater protrusion 209 is sized toreceive a resistive heater element 211 as described above with respectto step 109. The resistive heater element 211 is operated under controlof the surface (or downhole) control equipment 213 to heat the adjacentrock matrix 205 to a temperature that mobilizes (and/or vaporizes)condensate near the producing interval of the well in order to limit thebuildup of condensate near the producing interval of the well.Production tubing (not shown) extends from the producing interval to thewellhead (not shown). The production tubing is used to produce naturalgas (and possibly condensate) from the producing interval of the wellwhile concurrently using the surface control equipment 213 to operatethe heater element 211 to heat the adjacent rock matrix 205 to atemperature that mobilizes (and/or vaporizes) condensate near thecompleted producing interval 203 of the well.

FIG. 6 also shows a graph that depicts the level of condensate as afunction of position in the rock matrix 205 relative to the heaterprotrusion 209 for the case where the heater element 211 is not used toheat the rock matrix 205 as well as the case where the heater element211 is used to heat the rock matrix 205. The heating of the rock matrix205 is sufficient to cause condensate to vaporize into gas. Once gas isgenerated, it will flow in the direction of low pressure, which in thiscase, is the producing interval 203 of the well. In addition tovaporization, the temperature increase can also reduce the viscosity ofthe liquid phase condensate, thus improving the mobility of the liquidphase condensate and causing it to flow into the completed producinginterval 203 of the well. Both these mechanisms reduce the amount ofcondensate and help increase the gas flow rate.

The protrusion 207 of FIG. 6 cooperates with the heating of the rockmatrix 205 by the proximate heater element 211 to facilitate productionof the condensate. For the case where the liquid phase condensate in therock matrix 205 is heated to a temperature that is sufficient to causethe condensate to vaporize into gas, the gas moves in the direction ofthe completed producing interval 203 and up at the same time. Once thegas reaches the protrusion 207, the gas can easily travel to theproducing interval and be produced. In this case, the liquid phasecondensate in the rock matrix 205 can be heated to sufficienttemperature that will lower the viscosity and density of the liquidphase condensate and thus improve its mobility. These factors worktogether to move the liquid phase condensate in the direction of thecompleted producing interval 203 as well as up. Once this liquid phasecondensate reaches the perforation 207, it can easily travel to thecompleted producing interval and be produced.

The rock matrix 205 conducts the heat generated by the heater element211 within its own body and transfers it to condensate by means ofconvection. In one embodiment, the heat transferred to the condensate issufficient to vaporize the condensate (i.e., overcome its phase boundaryfor its vapor pressure). Depending on the thermal diffusivity (a) of theformation material, heat can be transferred either quickly or slowly tothe condensate. As shown from the following equation 2, in a substancewith high thermal diffusivity, heat moves rapidly through because thesubstance conducts heat quickly relative to its volumetric heatcapacity:

$\begin{matrix}{\alpha = \frac{k}{\rho \; c_{p}}} & {{Eqn}.\mspace{14mu} (2)}\end{matrix}$

where κ is the thermal conductivity (W/(m·K)) of the rock matrix, ρ isdensity (kg/m³) of the rock matrix, c_(p) is the specific heat capacity(J/(kg·K)) of the rock matrix, and thus ρ c_(p) is the volumetric heatcapacity (J/(m³·K)) of the rock matrix.

Sandstone formation has a thermal diffusivity of 1.81×10⁻⁶ m²/s⁻¹ whilelimestone formation has thermal diffusivity of 1.14×10⁻⁶ m²/s;therefore, it is expected sandstone to transfer heat much quicker thanlimestone. Once the heat source is switched on, one would expect heatflux in all directions from the protrusion which will generatetemperature gradients in all directions. To calculate such temperaturedistributions within the reservoir and wellbore, thermal exchanges dueto conduction and convection need to be considered as well the effectsof heating the condensate. The expected temperature profile close to thewellbore compared to the energy source is shown in FIG. 7.

Approximately 2.2 kJ is required to raise a unit mass of condensate by1° C. at constant pressure. Assuming the heat is being transferred fromthe rock surface to the condensate, the amount of heat transferred intothe condensate during a period of time equals the increase in the energyof the condensate during the time period according to:

hA _(s)(T _(s) −T _(∞))=mc _(p)(T _(∞) −T _(i))  Eqn. (3)

where T_(i) is condensate initial temperature, T_(s) is rock surfacetemperature, T_(∞) is finite/equilibrium temperature, m is condensatemass in kg, c_(p) is the specific heat capacity (J/(kg·K)) of the rockmatrix, h is the heat transfer coefficient between rock and condensatein W/m²° C., and A_(s) is the surface cross-section area in m². If thedew point temperature is known at reservoir pressure, then the energyrequirements can be calculated using equation 2. Then from equation 3,the surface rock temperature is calculated and can be related to energyrequired to be transferred within the rock body itself. Moreparticularly, via geometrical modeling of the formation and identifyingthe boundary conditions, either analytical or numerical solutions forthe targeted zone can be applied and temperature profiles can becalculated within this zone.

According to one embodiment, a monitoring method to measure the flowrate of produced fluids is disclosed. The flow rate of produced fluidswithout heating can be measured, and the flow rate of produced fluidswith heating can be measured. The enhancement of the flow rate withheating relative to the flow rate without heating can be attributed tothe heating treatment. The flow rates can be measured downhole oruphole. The uphole measurement will generally integrate the flow ratefrom different parts of the reservoir and can lead to loss of depthinformation while the downhole measurement can usually be more resolved.Standard flow meters such as a venturi or a spinner can be used for thispurpose. Commercial tools exist that can perform these measurements. Ifthe flow rate is measured downhole by a flow meter 251 as shown in FIG.8, it is possible to place the flow meter 251 (or multiple flow meters)at different depths relative to the condensate reservoir and record theflow measurements at the data recording and analysis system 253 withmore information content. For example, the flow meter 251 and datarecording and analysis system 253 can cooperate to record flow ratemeasurements at different points ranging from below the heating element211 to the top of the reservoir, which should provide a good indicationof where the gas is coming from and at what rate.

Another monitoring method measures the pressure and temperature in thecondensate reservoir as a function of depth from below the heatingelement to the top of the reservoir. This can be done by placingtemperature sensors and pressure sensors (such as a fiber opticdistributed temperature and pressure sensor 255) behind the productioncasing 201 at the time of completion as shown in FIG. 8. The sensorscooperate with a system 257 to measure the pressure and temperature inthe condensate reservoir as a function of depth from below the heatingelement to the top of reservoir. The measurements can be recorded bysystem 253. The temperature and pressure of the condensate reservoir inthe vicinity of the heater element 211 can be measured as a function oflateral distance (offset) into the formation by placing temperaturesensors and pressure sensors (such as a fiber optic distributedtemperature and pressure sensor 259) into the formation in the vicinityof the heater element 211 as shown.

It should be appreciated that FIG. 8 shows one embodiment wherein a holehas been drilled in the radial direction and a temperature sensor hasbeen inserted into the hole. A cased hole dynamics tester CHDT tool ofthe assignee can be used to drill the hole. As previously suggested, thetemperature sensor is a distributed temperature sensor that can sensethe temperature variation as a function of depth into the formation. Inanother embodiment, the measurements from a plurality of temperaturesensors distributed along the axis of the well can be used to determinea radial dependence of temperature. In embodiments, the sensorscooperate with the system 257 to measure the pressure and temperature inthe condensate reservoir in the vicinity of the heater element 211 as afunction of lateral distance (offset) into the formation. Themeasurements are recorded by system 253. The temperature and pressuremeasurements recorded by system 253 can be analyzed to characterize thetemperature and pressure of the condensate reservoir as needed. Suchanalysis can involve continuous monitoring. In alternate embodiments,the temperature and pressure measures can be measured and transmitted tothe surface; this may include wireless telemetry, or a cable.Alternatively, the measurements can be made by a recording unit that ispositioned in the well as desired.

It is contemplated that the methodology and system as described hereincan be utilized in a new production well for a condensate gas reservoir.It is also contemplated that the methodology and system can be used toadd condensate heating capability to an existing production well for acondensate gas reservoir in which case some of the steps in FIG. 5, suchas drilling the well and completion, do not need to be performed at thetime of this treatment.

The amount of thermal energy injected into the formation can be adjustedbased on preset objectives. At one extreme, the objective may be toevaporate most of the condensate by injecting a relatively large thermalenergy into the formation for a relatively short time. At anotherextreme, the objective may be to use a minimum amount of thermal energy.In this case the condensate will increase as a function of time,although at a slower rate compared to the case where there is noheating. Between these extremes there are many scenarios where thermalenergy is adjusted to increase (or keep constant) the level of gasproduction and then kept at that level. These scenarios can beimplemented by adjusting the electrical current into the heatingelements using an uphole control or a control device located downhole.

There have been described and illustrated herein several embodiments ofa methodology and apparatus for producing fluids from a condensate gasreservoir. While particular embodiments of the invention have beendescribed, it is not intended that the invention be limited thereto, asit is intended that the invention be as broad in scope as the art willallow and that the specification be read likewise. Thus, whileparticular configurations for a vertical production well have beendisclosed, it will be appreciated that other similar configurations forhorizontal production wells and multilateral production wells as well.In addition, while particular types of completion equipment of theproduction well have been disclosed, it will be understood that othersuitable completion equipment can be used. It will therefore beappreciated by those skilled in the art that yet other modificationscould be made. Accordingly, all such modifications are intended to beincluded within the scope of this disclosure as defined in the followingclaims. In the claims, means-plus-function clauses, if any, are intendedto cover the structures described herein as performing the recitedfunction and not only structural equivalents, but also equivalentstructures. It is the express intention of the applicant not to invoke35 U.S.C. §112, paragraph 6 for any limitations of any of the claimsherein, except for those in which the claim expressly uses the words‘means for’ together with an associated function.

What is claimed is:
 1. A method of producing reservoir fluids from acondensate gas reservoir traversed by a production well, comprising:forming at least one protrusion in or adjacent to a producing intervalof the gas reservoir, wherein the protrusion is configured to receive aheater element; placing the heater element into the protrusion andconfiguring the heater element for operation; and producing reservoirfluids from the producing interval while operating the heater element.2. A method according to claim 1, wherein: the heater element isconfigured to raise the temperature of reservoir adjacent to theprotrusion to vaporize the condensate that is proximate the heaterelement.
 3. A method according to claim 1, wherein: the protrusionconfigured to receive the heater element is formed by a device selectedfrom the group consisting of a perforation gun, a high power laser, acasing drilling instrument, and a direction drilling tool.
 4. A methodaccording to claim 1, further comprising: forming a productionprotrusion in the producing interval of the gas reservoir, wherein theproduction protrusion is located proximate to an associated protrusionfor the heater element.
 5. A method according to claim 4, wherein: theproduction protrusion is formed by a device selected from the groupconsisting of a perforation gun, a high power laser, a casing drillinginstrument, and a direction drilling tool.
 6. A method according toclaim 4, wherein: said forming a production protrusion compriseshydraulic fracturing.
 7. A method according to claim 1, wherein: theheater element comprises a resistive heater element.
 8. A methodaccording to claim 1, wherein: the heater element comprises an antennathat directs electromagnetic radiation.
 9. A method according to claim8, wherein: said electromagnetic radiation is generated by a downholesource of electromagnetic radiation together with conductors or awaveguide that supplies electromagnetic energy generated by the sourceto the antenna.
 10. A method according to claim 1, wherein: the heaterelement is supplied with heat from an external heat source.
 11. A methodaccording to claim 1, further comprising: injecting metal particles intothe reservoir adjacent to the protrusion.
 12. A method according toclaim 11, wherein: said metal particles are metal nanoparticles.
 13. Amethod according to claim 1, further comprising: monitoring the flowrate of produced reservoir fluids.
 14. A method according to claim 1,further comprising: monitoring at least one temperature and pressure ofthe condensate reservoir as a function of location along the producinginterval.
 15. A method according to claim 1, further comprising:monitoring at least one temperature and pressure of the condensatereservoir in the vicinity of the heater element as a function of radialoffset away from the borehole wall.
 16. A method according to claim 1,further comprising: measuring a rate at which the reservoir fluids areproduced and controlling the heating element in order to control saidrate.
 17. A system for producing reservoir fluids from a condensate gasreservoir traversed by a production well, the system comprising: atleast one heater element that is configured for disposition inside aprotrusion in or adjacent to a producing interval of a gas reservoir;equipment coupled to and configured to operate the at least one heaterelement; and wherein the heater element is configured to heat thereservoir proximate the heater element, reducing condensate build up.18. A system according to claim 17, wherein: the heater element isconfigured to heat the natural gas bearing rock that is proximate theheater element to a temperature that is sufficient to vaporize thecondensate that is proximate the heater element.
 19. A system accordingto claim 17 further comprising: a perforated casing, wherein theprotrusion for the at least one heater element is located below andproximate to at least one perforation in the casing located along theproducing interval of the production well, the perforation providingfluid communication between the natural gas bearing rock and theproducing interval of the production well.
 20. A method of producingreservoir fluids from a condensate gas reservoir traversed by aproduction well, comprising: forming at least one protrusion into a rockbearing natural gas along or adjacent a producing interval of the gasreservoir, the protrusion extending in a substantially radial directionaway from the central axis of the production well into the rock, whereinthe protrusion is configured to receive a heater element; placing theheater element into the protrusion and configuring the heater elementfor operation by surface located equipment; and producing reservoirfluids from the producing interval of the gas reservoir while operatingthe heater element to heat the natural gas that is proximate the heaterelement, whereby heat supplied by the heater element reduces condensatebuild up in the rock during the production of reservoir fluids from theproducing interval.
 21. A method according to claim 20, furthercomprising: forming a production protrusion in the producing interval,wherein the production protrusion is located proximate to an associatedprotrusion for the heater element.
 22. A method according to claim 21,further comprising: perforating a casing to form at least oneperforation along the producing interval, the perforation providingfluid communication between the production protrusion and the productionwell, wherein the perforation is located above and proximate to anassociated protrusion for a respective heater element.